Page 1

Recent Developments in the Levelized Cost of Energy from U.S. Wind Power Projects Ryan Wiser, Lawrence Berkeley National Laboratory Eric Lantz, National Renewable Energy Laboratory Mark Bolinger, Lawrence Berkeley National Laboratory Maureen Hand, National Renewable Energy Laboratory February 2012 This analysis was funded by the Wind & Water Power Program, Office of Energy Efficiency and Renewable Energy of the U.S. Department of Energy under Contract No. DE-AC02-05CH11231 1


Background and Motivation •  Some recent focus has been placed on the increasing capital cost of wind projects observed from the early 2000s to 2010, and the apparent flattening of fleet-wide capacity factors in recent years •  These trends are important, but ignore other developments: –  Continued improvements in capacity factors within individual wind resource classes (if not fleet-wide) due to hub height and rotor diameter scaling –  Significant recent improvements in low-wind-speed technology, resulting in increased capacity factors and increased land area open to development –  Steep reductions in turbine prices negotiated in last 2 years, and some evidence of reductions in balance of plant costs  expected (with some lag) to lead to sizable near-term reductions in project-level capital costs –  Possible longer-term (i.e., since early 2000s) reductions in the cost of operating and maintaining as well as financing wind projects, as well as potentially improved turbine/project availability –  Incentive choice with respect to 30% ITC/1603 Treasury grant in lieu of PTC 2


Background and Motivation •  Exclusive focus on historical capital cost and fleet-wide capacity factor trends fails to convey recent improvements in the levelized cost of energy (LCOE) from wind projects, the opening of new lower-wind-speed areas for development, and the fundamental interdependency of capital costs and capacity factors •  Wind turbine manufacturers, wind project developers, and wind power purchasers are not focused solely on optimizing capital costs and capacity factors, individually, but are more interested in: –  Levelized cost of wind energy across all wind resource classes •  Lower LCOE  lower power sales prices  greater demand for wind energy

–  Amount of land area that might be reasonably developed •  Transmission/siting/policy influences can constrain development in high-windresource regimes  opening new lower-wind-resource regimes for development can significantly increase potential development opportunities

3


Objectives of Present Work (1) Develop consistent levelized cost of energy estimates for wind in the U.S. in various wind resource regimes for: –  Projects installed in 2002-2003: The low-point of wind capital costs –  Projects installed in 2009-2010: The likely peak of wind capital costs –  Projects to be installed in 2012-2013: When current turbine pricing is likely to more-fully make its way into observed capital costs

Focus on direct costs, accounting primarily for capital cost trends and trends in estimated capacity factors; conduct analysis with/without PTC/ MACRS; emphasize, only as an example, GE turbines

(2) Estimate the amount of available land area that would exceed certain capacity factor and LCOE thresholds using the same assumed technology, assumptions, and time periods as above (3) Conduct two side-case analyses: (1) impact of incentive choice between PTC and ITC/Section 1603; and (2) impact of possible O&M, financing, and availability trends 4


Caveats •  This is a preliminary assessment of the impact of various trends on LCOE; the analysis does not consider all factors, and the results have not undergone rigorous peer-review or been published •  The analysis uses GE turbine technology only as an example to facilitate assessment •  This work only seeks to understand and estimate recent and near-term developments •  LCOE estimates for 2012-2013 are based on current turbine pricing, but are nonetheless speculative •  This work has not attempted to track developments over a longer historical record or to forecast longer-term future trends •  The present analysis is focused on the U.S., though the basic findings should hold for other regions of the world as well 5


Presentation Outline

Recent Trends

Analysis Assumptions

6

Analytical Results


Datasets Used To Explore Recent Capital Cost and Performance Trends Project- and TurbineLevel Capital Costs

•  488 projects built from 1983-2011, 34.6 GW •  81 turbine transactions from 1997-2011, 23.9 GW

Project-Level Performance / Capacity Factors

•  338 projects built from 1983-2009, 32.0 GW

Data shown here are primarily from the U.S. DOE’s 2010 Wind Technologies Market Report (“U.S. DOE 2011”) 7


Installed Wind Project Capital Costs Increased from Early 2000s through 2010 5,000

Installed Project Cost (2010 $/kW)

4,500

Individual Project Cost (488 projects totaling 34,616 MW) Capacity-Weighted Average Project Cost Polynomial Trend Line

4,000 3,500 3,000 2,500 2,000 1,500 1,000 500

1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

0

Source: U.S. DOE 2011

Project costs bottomed out in 2001-2004; rose by $850/kW on average through 2009; held steady in 2010 ($2,155/kW); based on limited available data, may have dropped in 2011 8


Fleet-Wide Capacity Factors (CF) Have (Generally) Increased Over Time 35%

Some leveling off in fleet-wide capacity factors in recent years is also apparent

25% 20% 15%

10% 5% 0% Year: 1999

Projects:

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

12

41

85

98

118

144

169

212

256

358

338

6

MW: 549

1,005 1,545 3,285 3,826 5,182 5,894 8,726 10,712 15,686 24,403 31,986

50% 2010 Capacity Factor (by project vintage)

BUT:

Capacity Factor

30%

45% 40%

Sample includes 338 projects totaling 32 GW

35% 30% 25% 20% 15% 10%

Capacity-Weighted Average 2010 Capacity Factor (by project vintage)

5%

Individual Project 2010 Capacity Factor (by project vintage)

0%

Source: U.S. DOE 2011

Pre-1998

1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

9 projects

22 projects

25 projects

35 projects

31 projects

19 projects

34 projects

76 projects

87 projects

1,553 MW

1,906 MW

3,414 MW

1,591 MW

4,718 MW

8,409 MW

8,967 MW

647 MW

9 780 MW


Historical Trends Important, But Ignore Other Notable Developments Project Performance

•  Sizable historical/continued increases in hub heights and rotor swept area (in proportion to nameplate capacity), leading to improvements in capacity factors within individual wind resource classes, especially in lower-wind-speed sites

Installed Capital Costs

•  Steep reductions in wind turbine prices negotiated over the last 2 years, with some evidence of a simultaneous reduction in balance of plant costs, which are expected to lead to sizable near-term capital cost reductions

Other Possible Advancements

•  Operation and maintenance: Potential reduction in the cost of O&M for newer wind power projects •  Financing: Notwithstanding the impact of the financial crisis, generally improved financing terms over the longer-term as the sector and technology have matured •  Availability: Potential reduction in losses due to improved turbine/project availability

(since early 2000s)

See following slides for more details… 10


Recent Moderation of CF Increase Driven In Part By Move Towards Lower Wind Speed Sites… Projects increasingly sited in poorer wind regimes at 50m: •  1998-2001: Class 4-5 common •  2006-2009: Class 3-4 common Trend likely driven by transmission/siting limitations and policy influences, as well as improvement in low wind speed technology 900

Wind Power Density at Project Level

Class 7

Wind Power Density  (Average, W/m2 @ 50 m)

800 Class 6

700 600

Class 5

500

Class 4

400

Class 3

300 200 100 0

Class 2

Note: Box plots identif y 10th/25th/75th/90th percentile values Percentages in labels represent % of total in LBNL database

Project Level Capacity Weighted Mean Project Level Median

Class 1

1998‐99             2000‐01             2002‐03             2004‐05              2006                       2007                       2008                       2009                       48 projects       43 projects       50 projects       54 projects       38 projects  53 projects  108 projects  88 projects       988 MW      1725 MW  2067 MW  2611 MW  2455 MW  5250 MW  8169 MW  9479 MW  (97%) (98%) (97%) (93%) (100%) (100%) (98%) (95%)

Source: Lawrence Berkeley National Laboratory 11


…and Growing Amounts of Wind Energy Curtailment in Some Regions Wind Curtailment, GWh (percent potential generation)

2007

2008

2009

2010

Electricity Reliability Council of Texas

109 (1.2%)

1,417 (8.4%) 0 (0.0%) 2.5 (0.1%) 25.4 (0.8%)

3,872 (17.1%) 0 (0.0%) 19.0 (0.6%) 42.4 (1.2%) 250 (2.2%)

2,067 (7.7%) 0.9 (0.0%) 81.5 (2.2%) 42.6 (1.2%) 781 (4.4%) 4.6 (0.1%) 2,978 (5.1%)

Southwestern Public Service Co.

N/A

Public Service Company of Colorado

N/A

Northern States Power Co.

N/A

Midwest ISO, less NSP

N/A

N/A

Bonneville Power Administration

N/A

N/A

N/A

109 (1.2%)

1,445 (6.4%)

4,183 (10.4%)

Total Across These 6 Areas: Source: U.S. DOE 2011

U.S. fleet-wide capacity factors from 2008-2010 would have been 1-2 percentage points higher absent curtailment (curtailment largely caused by inadequate transmission and minimum load) 12


Move to Lower Wind Speed Sites and Increased Curtailment Hide the Very Real Increases in CFs Witnessed in Individual Wind Resource Classes Average Rotor Diameter and Hub Height (m)

90 80 70 60

Rotor Diameter

50

Hub Height

Historical increases in avg. hub height and rotor diameter have been substantial

40 30 20 10 0

Turbines: Capacity:

1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

2010

1,418

1,982

1,686

1,942

1,515

3,190

5,004

5,733

2,855

1,014 MW 1,756 MW 2,080 MW 2,779 MW 2,440 MW 5,249 MW 8,348 MW 9,993 MW 5,113 MW

Source: U.S. DOE 2011

Leading to sizable increases in avg. capacity factors within specific resource classes

50% Capacity Factor (Weighted Average)

COD:

45% 40%

35% 30% 25%

20%

2005-2007 Projects

15%

2002-2004 Projects

10%

1998-2001 Projects

5% 0% 1

2

3

4 5 6 Wind Resource Class @ 50m

Source: Lawrence Berkeley National Laboratory 13

7

8


Wind Turbine Prices Have Softened Since Their Highs in 2008 Lag between turbine prices and project costs should lead to substantial project-level installed capital cost reductions by 2012-2013

Source: Bolinger and Wiser 2011

Turbine price quotes in 2011 for “standard� technology are reportedly as low as $900/kW (Tier 1: ~$1,100-1,250/kW, with average at ~$1,100/kW); higher costs typical for smaller orders, larger rotors/towers, etc. (also more-favorable terms for buyers and improved technology; balance-ofplant costs also reportedly lower than in recent past) 14


Some Evidence of Lower O&M Costs, Higher Availability, Improved Financing 30

Commercial Operation Date (projects >5 MW only):

O&M costs from limited sample of US wind power projects (U.S. DOE 2011)

Median O&M Cost (2010 $/MWh)

25

1998-2003

2004-2009 20 15

10

1

2

3

4

5

6

7

n=3

n=3

n=2

n=2

n=4

n=3

n=7

n=7

n=19

n=13

n=21

n=27

n=29

n=34

0

n=16

5

8

9

10

Number of Years Since Commercial Operation Date

Strength of evidence supporting specific improvements in O&M, availability, and financing somewhat lower than trends in capacity factor and capital cost

GE’s reported median availability by model year (Mesh et al. 2011, “GE Wind Turbine Availability)

15


Recent “Chatter” Suggests that, As a Result of These Trends, Delivered Wind Energy Costs Have Declined Substantially BNEF 2011: "The cost of wind generation has been driven to record lows by declines in turbine prices and the cash grant, which eliminates the cost of securing tax equity financing.” “Austin Energy officials say those wind contracts are among the cheapest deals available, when the cost of building power plants is taken into account, and comparable to what the historically volatile natural gas market has been offering recently.” (Statesman.com article) “Our contract with NextEra Energy Resources is one of the lowest we’ve ever seen and results in a savings of nearly 40 percent for our customers,” said David Eves, president and CEO of Public Service Company of Colorado. “The addition of this 200-megawatt wind farm demonstrates that renewable energy can compete on an economic basis with more traditional forms of generation fuel, like natural gas, and allows us to meet the state’s Renewable Energy Standard at a very reasonable cost to our customers.” (Reuters article) Consumers Energy, Michigan: "Lower wind power costs mean $54m saving for Consumers Energy.“ (newspaper article) Westar, Kansas: Signed more wind contract than needed "...because pricing is so attractive now and to minimize tax risk to our investors" (Westar Q4 earnings call)

16


Presentation Outline

Recent Trends

Analysis Assumptions

17

Analytical Results


Analysis Objective Estimate Capacity Factors, LCOE, and Developable Land Area By Selecting Representative Assumptions for Turbines Used in U.S. Wind Projects Installed in 2002-2003

•  The low-point of wind project capital costs

Installed in 2009-2010

•  The likely peak of wind project capital costs

(To be) Installed in ~2012-13

•  When current turbine pricing is likely to morefully make its way into observed capital costs

18


Basic Approach In each period, account for common actual/expected trends in: (1)  installed capital costs (based on actual/estimated cost) (2)  capacity factors in different wind resource classes (estimated based on available power curves, assuming sea level air density of 1.225 kg/m3)

For simplicity, in most cases hold constant: O&M costs; financing structure and costs; project/turbine availability and other losses; project life, income taxes, decommissioning, etc. Estimate LCOE: (1) without PTC or 5-yr MACRS (depreciation assumed to be 12-yr straight line); and (2) with PTC and 5-yr MACRS Conduct two side analyses: (1) impact of incentive choice between PTC and ITC/Treasury Grant; and (2) impact of possible O&M, financing, and availability trends Use IEA Task 26 Work-package 1 LCOE model 19


For Analytical Simplicity, Focus on GE Turbine Evolution Typical GE Turbine Offerings Over Time (does not include 2.5 MW turbine platform)

GE has been the dominant supplier of turbines to the U.S. market over this timeframe, ensuring that a focus on GE as an example of the evolution of cost, performance, and LCOE trends is appropriate 20


Summary of Core Input Assumptions Characteristics

2002-2003

2009-2010

Standard

Standard

Standard*

Low Wind*

Low Wind*

1.5 MW

1.5 MW

1.62 MW

1.62 MW

1.62 MW

65 m

80 m

80 m

80 m

100 m

Rotor diameter (RD)

70.5 m

77 m

82.5 m

100 m

100 m

Installed capital cost

$1,300/kW

$2,150/kW

$1,600/kW

$1,850/kW

$2,025/kW

Operating costs

$60/kW-yr

$60/kW-yr

$60/kW-yr

$60/kW-yr

$60/kW-yr

Losses (availability, array, other)

15%

15%

15%

15%

15%

Financing (nominal)

9%

9%

9%

9%

9%

Technology type Nameplate capacity Hub height (HH)

•  •  •  •  •  •  • 

Dollar values are all real 2010$ Financing cost / discount rate reported in nominal terms Air density = 1.225 kg/m3 (sea level wind speed) Weibul K Factor = 2 in all scenarios 1/7th power law scaling to estimate hub height wind speed 20-year assumed project/economic life in all scenarios Aggregate income taxes assumed to equal 38.9%

Current Turbine Pricing: ~2012-2013

All assumptions intended to reflect representative actual/common conditions; installed costs, operating costs, losses and other assumptions can vary considerably from one project to the next

*These turbines are assumed viable in sites up to the respective IEC Class II and Class III reference average annual wind speed. Depending on site specific gust, turbulence, and air densities these turbines in actuality may be 21 annual wind speeds than applied in this analysis. reasonably placed in sites with higher average


Basis For Core Assumptions Turbine Characteristics (capacity, hub height, rotor diameter) –  Common GE designs for relevant installation years

Installed Capital Cost –  2002-2003 and 2009-2010: based on actual average costs for installed projects –  2012-2013: assumes $550/kW drop in turbine/BOP costs since high-point for 80 m HH / 82.5 m RD turbine based on earlier data on turbine cost trends, BNEF (2011), and discussions with wind developers/manufacturers; $250/kW assumed increase for 100 m RD upgrade and additional $175/kW increase for 100 m HH upgrade based on discussions with wind developers/manufacturers; result is an estimate of the average installed cost of projects based on current turbine orders; actual project costs will have a large spread around the average, with both lower- and higher-cost projects anticipated

Other Costs and Characteristics –  Operating costs: Assumed to be exclusively denominated in $/kW-yr, though, in practice, some costs may be more-appropriately denominated in $/MWh; all-in operating costs assumed to equal $60/kW-yr in core analysis based on review of available data/literature –  Losses: 15% losses assumed in core analysis based on review of available data/literature, as well as matching actual and estimated project-level capacity factors –  Financing: 9% assumed in core analysis based on review of available data/literature 22


Summary of Side-Case Input Assumptions Incentive Choice

•  Assumes that project owners choose between the PTC and ITC/Treasury Grant based only on the face-value of those incentives (i.e., the incentive that minimizes the LCOE with no additional changes and ignoring any ancillary benefits of the ITC/Treasury Grant)

O&M, Financing, Availability

•  O&M: Cost reduction from $64/kW-yr in 2002-2003  $57/kW-yr in 2012-2013 based on review of available data/literature, including 2010 Wind Technology Market Report, BNEF (2011), etc. •  Financing: All-in cost of finance decreases as technology matures from 10.5% in 2002-2003  9% in 2012-2013 based on review of available data/ literature and discussions with wind developers •  Availability: Reduction in average project-level losses from 16.5% in 2002-2003  14% in 2012-2013 based only on assumed improvement in availability, itself based on review of limited available data/ literature and discussions with wind consultants and developers 23


Presentation Outline

Recent Trends

Analysis Assumptions

24

Analytical Results


Outline of Key Results Estimated Capacity Factors in Varying Resource Classes Levelized Cost of Energy in Varying Resource Classes Side Analysis: Impact of Improvements in O&M, Financing, and Availability Designing Turbines for Low Wind-Speed Sites: Narrowing the Gap in LCOE Side Analysis: Impact of ITC/Treasury Grant Option In Lieu of PTC Increased Land Area Exceeding Capacity Factor Thresholds Increased Land Area Exceeding LCOE Thresholds 25


Turbine Design Advancement Leads To Enormous Increase in Capacity Factors Estimated capacity factor improvement driven by larger rotor swept area in proportion to nameplate capacity, as well as higher hub heights; increase is especially apparent with newest batch of low-wind-speed turbines 50% Current: 2012‐13  Low Wind‐speed (100m Tower)

45%

Current: 2012‐13  Standard Technology

Current: 2012‐13  Low Wind‐speed (80m Tower)

2009‐10 Standard Technology

Capacity Factor

40%

2002‐03 Standard Technology

35% 30%

Note: Low wind-speed turbine performance is modeled up to a 7.5 m/s hub height wind speed, per IEC standards; site specific conditions may allow these machines to be installed in wind regimes that exceed the IEC average annual wind speed, leading to higher capacity factors (at higher average 50m wind speeds) than shown here.

25% 20% 15% 5.5

6.0 Class 2

6.5

7.0

7.5

Class 3                Class 4                 Class 5 50m Wind‐speed (m/s)  26 air density = 1.225 kg/m3

8.0

8.5 Class 6


Levelized Cost of Wind Energy Is Estimated To Be at An All-Time Low for 2012-2013 Accounting only for assumed capacity factor and capital cost trends, LCOE increased substantially from 2002-2003 to 2009-2010 because capital cost increases were not fully compensated by CF improvements; estimated LCOE has since dropped below its earlier lows within individual wind resource classes because capital cost increases from 2002-2003 to the present have been more-than offset by CF improvements, yielding a lower LCOE than at any time in the past within individual resource classes

Without Federal Incentives

With Federal PTC/MACRS

$120

$120

$100

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

Levelized Cost of Energy ($/MWh) No Incentives

Mid‐Class 3 

Mid‐Class 5

$80

$60 $40 $20 $0 2002‐03: Standard Tech.

2009‐10: Standard Tech.

Current, 2012‐13 Tech. Choice

$100

$80

Mid‐Class 3 

$60

Mid‐Class 5

$40 $20 $0 2002‐03: Standard Tech.

2009‐10: Standard Tech.

Current, 2012‐13 Tech. Choice

Note: “Tech. Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 27


Levelized Cost of Energy in Varying Resource Classes (without PTC/MACRS) Based on current pricing and assumptions: 100m rotor diameter is found to be economically attractive in comparison to 2012-2013 ‘Standard Technology’ where it can be deployed; a wind sheer higher than 1/7th is found to be needed for the 100m tower to be least cost in comparison to the 80m option (with the 100m rotor) Levelized Cost of Energy ($/MWh)  No Incentives

$160 $140

1

$120

2

2009‐10: Standard  Technology

$100 $80 $60

2002‐03: Standard  Technology

Current, 2012‐13:  Low Wind‐speed  (100m Tower)

$40

Current, 2012‐13:  Standard  Technology

Current, 2012‐13:  Low Wind‐speed  (80m Tower)

$20 $0 5.5

6.0 Class 2

6.5

7.0

7.5

Class 3                  Class 4            Class 5 50m Wind‐speed (m/s)  (air density = 1.225 kg/m3 )

28

8.0

8.5 Class 6


Levelized Cost of Energy in Varying Resource Classes (with PTC/MACRS) With PTC/MACRS and with02-03 currenttoturbine andsince otherdropped specific assumptions, LCOE increased from 09-10,pricing but has below its the highest wind speedthe sites evaluated support asthe low present as ~$33/ earlier lows despite increase in below capitalcan cost from LCOEs 02-03 to MWh (real$), while the lower wind speed sites have LCOEs of ~$65/MWh Levelized Cost of Energy ($/MWh)  Includes Federal PTC & MACRS

$120 1

$100

2

$80

2009‐10: Standard  Technology

$60 $40

2002‐03: Standard  Technology

Current, 2012‐13  Low Wind‐speed  (100m Tower)

$20 $0 5.5

6.0 Class 2

6.5

Current, 2012‐13:  Low Wind‐speed  (80m Tower)

Current, 2012‐13:  Standard Technology

7.0

8.0

7.5

Class 3                Class 4                Class 5 50m Wind‐speed (m/s) air density = 1.225kg/m3

29

8.5 Class 6


All Else Being Equal, Capital Cost Increases Would Have Led To Much Higher LCOEs (Mid Class 3 Wind Resource, with PTC/MACRS) Capital Cost Impacts on LCOE

Assumes Fixed Performance circa 2002‐03 and Class 3 Wind Resource

$100

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

$90 $80 $70 $60 $50 $40 $30 $20 $10

Current Pricing: Variable Turbine Designs

$0 2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.

30

2012‐13: Low Wind (80m Tower)

2012‐13: Low Wind (100m Tower)


All Else Being Equal, Performance Improvements Would Have Led To Much Lower LCOEs (Mid Class 3 Wind Resource, with PTC/MACRS) Performance Impacts on LCOE from Advanced Turbine Designs  Assumes Fixed Capital Cost circa 2002‐03 and Class 3 Wind Resource

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

$60 $50 $40 $30 $20 $10

Current Pricing: Variable Turbine Designs $0 2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.

31

2012‐13: Low Wind (80m Tower)

2012‐13: Low Wind (100m Tower)


Same Tradeoff Between Capital Cost and Performance Exists in Other Wind Resource Classes (Mid Class 5 Wind Resource, with PTC/MACRS) Capital Cost Impacts on LCOE

Performance Impacts on LCOE from Advanced  Turbine Designs 

$70

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

Assumes Fixed Performance circa 2002‐03 and Class 5 Wind  Resource

$60 $50

$40 $30

$20 $10 $0

2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.

32

Assumes Fixed Capital Cost circa 2002‐03 and Class 5 Wind  Resource $40

$35 $30 $25

$20 $15 $10 $5

$0 2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.


Same Tradeoff Between Capital Cost and Performance Exists without PTC/MACRS Class 3

Capital Cost Impacts on LCOE

Assumes Fixed Performance circa 2002‐03 and Class 3 Wind Resource

Assumes Fixed Capital Cost circa 2002‐03 and Class 3 Wind Resource

$90 $80 Levelized Cost of Energy ($/MWh) No Incentives 

$120 $100 $80 $60 $40 $20

Current Pricing: Variable Turbine Designs

$70 $60 $50 $40 $30 $20 $10

Current Pricing: Variable Turbine Designs

$0

$0 2009‐10: Standard Tech.

2012‐13: Standard Tech.

2012‐13: Low Wind (80m Tower)

Capital Cost Impacts on LCOE

2002‐03: Standard Tech.

2012‐13: Low Wind (100m Tower)

Assumes Fixed Performance circa 2002‐03 and Class 5 Wind  Resource

Class 5

2009‐10: Standard Tech.

2012‐13: Standard Tech.

2012‐13: Low Wind 2012‐13: Low Wind (80m Tower) (100m Tower)

Performance Impacts on LCOE from Advanced  Turbine Designs 

Assumes Fixed Capital Cost circa 2002‐03 and Class 5 Wind  Resource $70

$100 $90 $80 $70 $60 $50 $40 $30 $20 $10 $0

Levelized Cost of Energy ($/MWh) No  Incentives

2002‐03: Standard Tech.

Levelized Cost of Energy ($/MWh) No Incentives

Levelized Cost of Energy ($/MWh) No Incentives

$140

Performance Impacts on LCOE from Advanced Turbine Designs 

$60 $50

$40 $30

$20 $10 $0

2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.

33

2002‐03: Standard Tech.

2009‐10: Standard Tech.

2012‐13: Standard Tech.


Side Analysis: Impact of Improvements in O&M, Financing, and Availability (with PTC/MACRS) Assumed improvements in O&M costs, financing rates, and availability lead to substantial additional estimated LCOE reductions from 2002-2003 to 2012-2013 in comparison to core analysis that only varies capital cost and capacity factor

Core Assumptions

Side Analysis Assumptions

only varies capital cost and capacity factor

also varies O&M, availability, and financing $120

$100 $80

26% Cost Reduction 6 m/s 

$60

7 m/s

$40

8 m/s 5% Cost Reduction

$20 $0 2002‐03

Current, 2012‐13

Standard Technology

Technology Choice

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

$120

$100

$80

39% Cost Reduction 6 m/s

$60 7 m/s

$40

8 m/s 24% Cost Reduction

$20 $0 2002‐03

Current, 2012‐13

Standard Technology

Technology Choice

Note: “Technology Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 34


Side Analysis: Impact of Improvements in O&M, Financing, and Availability (without PTC/MACRS) Assumed improvements in O&M costs, financing rates, and availability lead to substantial additional estimated LCOE reductions from 2002-2003 to 2012-2013 in comparison to core analysis that only varies capital cost and capacity factor

Core Assumptions

Side Analysis Assumptions

only varies capital cost and capacity factor

also varies O&M, availability, and financing $140

20% Cost Reduction 6 m/s

$100 $80

7 m/s

$60

8 m/s 3% Cost Reduction

$40 $20

Levelized Cost of Energy ($/MWh) No Incentives

Levelized Cost of Energy ($/MWh) No Incentives

$120

$120

31% Cost Reduction 6 m/s

$100 $80

7 m/s

$60

8 m/s 17% Cost Reduction

$40 $20

$0

$0 2002‐03

Current, 2012‐13

2002‐03

Current, 2012‐13

Standard Technology

Technology Choice

Standard Technology

Technology Choice

Note: “Technology Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 35


Designing Turbines for Low Wind-Speed Sites: Narrowing the Gap in LCOE The proliferation of turbines designed for lower wind speeds has narrowed the gap between the LCOE of high- and low- wind speed sites, increasing the economic attractiveness of developing wind projects in lower wind speed areas Without Federal Incentives

With Federal PTC/MACRS

$100

$100

$80

$90

6 m/s $32/MWh

$70

7 m/s

$60

8 m/s

$25/MWh

$50 $40 $30 $20 $10

Levelized Cost of Energy ($/MWh) Includes Federal PTC & MACRS

Levelized Cost of Energy ($/MWh) No Incentives

$90

$80 $70 $60 $50

6 m/s $31/MWh 7 m/s

$40

$23/MWh

8 m/s

$30 $20 $10

$0

$0 Current, 2012‐13: Standard Technology

Current, 2012‐13: Tech. Choice Including Low Wind‐speed

Current, 2012‐13: Standard Technology

Current, 2012‐13: Tech. Choice Including Low Wind‐speed

Notes: Does not consider Treasury Grant program / 30% ITC (see later results); “Tech. Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 36


Side Analysis: Incentive Choice Has Also Impacted the Economics of Low Wind Speed Sites •  30% ITC/Grant applied to capital cost is relatively more lucrative than PTC on “facevalue” basis when a project has a low capacity factor and high costs  see results for 2009-2010 ‘Standard Technology’ in chart on left •  Current turbines / pricing have higher assumed capacity factors and lower costs, making PTC the better choice in virtually all developable wind regimes on “face value” basis  see results for 2012-2013 turbines in chart on right $110

$65

$100

Levelized Cost of Energy ($/MWh) 

$70

Levelized Cost of Energy ($/MWh) 

$120

2009‐10: Standard  Technology (PTC)

$90 $80

2009‐10: Standard  Technology  (ITC/Cash Grant)

$70 $60 $50 $40

2012‐13: Technology  Choice  (ITC/Cash Grant)

$60 $55 $50 2012‐13: Technology  Choice  (PTC)

$45 $40 $35 $30

$30 5.5

6.0

Class 2

6.5

7.0

7.5

8.0

8.5

Class 3 Class 4           Class 5           Class 6 50m Wind‐speed (m/s) 

5.5

6.0 Class 2

6.5

7.0

7.5

8.0

8.5

Class 3 Class 4            Class 5           Class 6 50m Wind‐speed (m/s) air density = 1.225 kg/m3

air density = 1.225 kg/m3

Note: Results ignore benefits of ITC/Treasury grant beyond direct face value; “Technology Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 37


Result Was Narrowing in LCOE Between High & Low Wind Sites in 2009-2010, Not in 2012-2013 ITC/Grant improved the economics of low wind speed sites in 2009-2010; estimated lower capital costs and improved capacity factors result in face value of PTC > ITC/Grant in 2012-2013 even in low wind speed sites (ancillary benefits of ITC/Grant may still outweigh loss in face value in such sites) $100

$100 6 m/s

$90

$80 $70

$45/MWh 7 m/s

$38/MWh

$60 8 m/s

$50 $40 $30

$20

Levelized Cost of Energy ($/MWh) Includes Federal Incentives

Levelized Cost of Energy ($/MWh) Includes Federal Incentives

$90

$80 $70 $60

6 m/s

$50 $40

$23/MWh

$23/MWh

7 m/s 8 m/s

$30 $20 $10

$10

$0

$0 2009‐10: Standard Technology PTC & MACRS

2012‐13: Tech. Choice Incl. Low Wind‐speed PTC & MACRS

2009‐10: Standard Technology Incentive Choice

2012‐13: Tech. Choice Incl. Low Wind‐speed Incentive Choice

Note: “Tech. Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 38


Land Area Exceeding Capacity Factor Thresholds Has Increased Dramatically Percentage Increase Since 2002-2003: > 30% CF: 80% – 140% > 35% CF: 130% – 270% > 40% CF: 600% – 1400%

3,000,000

Available Land Area (km2)

2,500,000

Current, 2012‐13:  Low Wind‐speed (100m Tower) [+ other 2012‐13 Turbines]

2,000,000

Current, 2012‐13:  Low Wind‐speed (80m Tower) [+ 2012‐13 Standard Tech]

1,500,000 Current, 2012‐13: Standard  Technology

1,000,000

2009‐10: Standard  Technology

500,000

2002‐03: Standard  Technology

0 28%

30%

32%

34%

36% 38% Capacity Factor

40%

42%

44%

Notes: Wind speed data come from the 50 m long‐term assessments produced by AWS Truepower, MN Dept of Commerce, Iowa State Energy Center,  AlternaEve Energy InsEtute (Texas), and NREL. Alabama, Louisiana, Mississippi, and Florida were not covered by any of these datasets. Standard wind  resource exclusions were applied, as documented on the Wind Powering America website. Low wind‐speed turbines are assumed to be uElized in sites  up to 7.5 m/s  sea level equivalent average annual wind‐speed, per IEC standards. Site specific condiEons may allow these machines to be placed in  higher average annual wind‐speed sites, which would further increase the percentage increase in available land area beyond what is esEmated here.  

39


Available Land Area (km2)

Land Area Exceeding LCOE Thresholds Has Also Increased Substantially 3,000,000

2012‐13: Lowest Cost Tech Choice

2,500,000

2002‐03: Standard Technology

2,000,000 1,500,000 1,000,000 500,000

Percentage Increase Since 2002-2003: < $35/MWh w/ PTC & MACRS: 42% < $55/MWh w/ PTC & MACRS: 48% < $75/MWh w/ PTC & MACRS: 25%

0 $30 $40 $50 $60 $70 $80 $90 w/:   PTC/MACRS w/o: PTC/MACRS           $57                       $67                      $77                      $89                      $99                     $110                    $121  Levelized Cost of Energy ($/MWh)

Notes: Increase in land area meeting a LCOE threshold is lower than the increase from a CF threshold because increased capital cost trends impact LCOE estimates, but not CF; “Tech. Choice” assumes that IEC Class III machines are only available for sites up to 7.5 m/s average wind speed at hub height (sea level air density) 40


Conclusions •  Economic attractiveness of wind projects in recent past was reduced due to increased capital cost, move toward lower wind speed sites, and lower electricity prices •  Examination of historical trends in capital costs and capacity factors, individually, gives an incomplete picture of technology advancement as well as historical & current developments •  Recent declines in turbine prices & improved technology have reduced the estimated LCOE of wind; LCOE for projects being planned today in fixed resource areas is estimated to be at an all-time low •  Considering plausible assumptions for not only capital cost and capacity factor, but also O&M, financing & availability, the LCOE for 2012-2013 projects is estimated to be as much as ~24% and ~39% lower than the previous low in 2002-2003 in 8 m/s and 6 m/s (at 50 m) resource areas, respectively (with the PTC/MACRS); when only considering capital cost and capacity factor, the reduction is ~5% and ~26% 41


Conclusions •  Technology advancement for lower wind speeds has narrowed the gap in LCOE between lower and higher wind speed sites; choice of 30% ITC/ Treasury Grant may have further encouraged development in lower wind speed sites, especially in 2009-2010 •  The amount of land area meeting or exceeding certain capacity factor and LCOE thresholds has substantially increased as a result of these technology improvements  helps alleviate to a degree transmission and siting barriers •  Technology advancement & learning still applies to onshore wind, despite its relative maturity, but all modes of technical advancement must be considered rather than emphasizing individual parameters •  Despite these recent and impressive technological advancements, three counter-veiling factors may intervene to raise LCOE: –  potential for increased pricing if demand for wind turbines begins to catch up with supply, or if other exogenous influences are triggered (e.g., higher commodities and/or labor costs) –  potential continued move towards lower wind speed sites as a result of severe transmission/siting limitations –  potential near-term loss of federal PTC/ITC/Treasury Grant 42

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